Elwood Brehmer

Supreme Court hears arguments in PFD veto lawsuit

Forty years to the day after the oil that generated the revenue to capitalize the Permanent Fund started flowing, the Alaska Supreme Court heard arguments over who controls distribution of the annual dividend payments of the Fund’s investment income. Anchorage Democrat Sen. Bill Wielechowski said the Permanent Fund Dividend is the primary reason Alaska has the lowest income inequality in the nation. “The PFD is unique; there’s nothing else like it in Alaska or the country for that matter,” he said to open his argument. Wielechowski, an attorney by trade, represented himself and former state Sens. Clem Tillion and Rick Halford before the court. The trio sued the Alaska Permanent Fund Corp. last September contending corporation officials violated state law when they adhered to Gov. Bill Walker’s partial veto of the 2016 dividend appropriation and transferred $695 million from the Permanent Fund Earnings Reserve to the Dividend Fund and not the full $1.36 billion that the formula in statute calls for and the Legislature approved. It was the first time a governor had vetoed any of the PFD amount. Tillion served in the Senate when the Permanent Fund was formed in 1976 and Halford was a state representative when the Legislature started the dividend program in 1982 and eventually served as Senate president. Superior Court Judge William Morse shot down their case last November, and concluded that eliminating the governor’s veto authority over the PFD would provide the Legislature more power than the Alaska Constitution provides. They immediately appealed to the Supreme Court. Walker made the bold move that some have called courageous and others have called stealing to send the message to Alaskans that their state is in a fiscal crisis and the status quo of government spending, and how it is paid for, is unsustainable, he said at the time and has continued to stress. The 2016 PFD would have likely been the largest in history at about $2,100 per person; Walker’s veto cut it to $1,022 each. The Alaska Constitution gives governors broad authority to make line-item vetoes in appropriations bills, and they regularly use it on budget bills. However, Walker also crossed out the language in the budget that notes the money transfer “is authorized under AS 37.13.145(b).” That is the statute that states the Permanent Fund Corp. “shall transfer” the formula-determined amount from the Earnings Reserve to the Dividend Fund for the annual payouts. Before the high court, Wielechowski agreed with Walker that the state is in a fiscal crisis, but called it a “crisis of government.” He also noted that the Legislature is free to appropriate from the Earnings Reserve of the Fund and change the law to reduce the dividend. That said, Wielechowski argued that until the Legislature changes the law to do that — which Walker has proposed and has bipartisan support in the Legislature — the dividend statute is indicative of a dedicated fund. It therefore mandates the Department of Revenue commissioner to calculate the lump sum dividend amount and the Permanent Fund Corp. to subsequently make the fund transfer, according to Wielechowski. “By the governor striking this statute he’s requiring the Permanent Fund Corp. to come up with an incorrect number,” he contended. Wielechowski said that after reviewing legislative records from when the Permanent Fund was formed by a voter-approved constitutional amendment in 1976 that, “All indications are that the Legislature intended to make this a dedicated fund.” The Alaska Constitution prohibits the Legislature from dedicating money to a particular cause, but the amendment to establish the Permanent Fund and divert at least 25 percent of state resource royalty revenue is one exception. Wielechowski stressed that the first three Dividend Fund transfers were made automatically, without language in the operating budget. Following that, for 26 years until the fiscal year 2010 budget, the transfer was made with just the language in the budget directing the transfer, he said. There was no dollar figure specified for appropriation. It all lends to the fact that the Dividend Fund to date has been treated by the Legislature as a dedicated fund, according to Wielechowski, and the budget line item and governor’s veto are therefore meaningless. Attorney Sonja Kawasaki, who argued the plaintiffs’ 10-minute rebuttal, called putting the PFD in the budget an “accounting notation” of the Legislature. Each side had 30 minutes to argue their case to the five Supreme Court justices. State Assistant Attorney General Kathryn Vogel represented the Permanent Fund Corp. Vogel said the amendment that formed the Permanent Fund mentions nothing of an annual citizen dividend or limits on the governor’s authority to veto appropriations. Further, she said the dividend formula statute does not approve spending without an appropriation and while a dedication can exist in law and prohibit some forms of appropriation, it simply binds the use of those funds and does not create a “hall pass” to supersede the need for an annual appropriation. “Fundamentally, there’s nothing about the dedicated fund clause not applying (to the Permanent Fund) that changes the normal course of appropriation,” Vogel argued. Federal funds the state receives are dedicated to specific causes but are still appropriated in each budget, she noted. Vogel continued to say that both sides in the case agree the PFD is a “statutory entitlement” that is not part of the constitutional amendment and therefore the governor’s veto authority holds. She concluded by saying the “veto struck what was a number described by words” and contended ruling for the senators would ostensibly give the 1982 Legislature that approved the first dividend formula binding authority over the Legislature and governor today. Chief Justice Craig Stowers wrapped up the argument hearing by thanking the audience for participating in such an important case but did not offer a timeline for a ruling. ^ Elwood Brehmer can be reached at [email protected]

State opens season for AK LNG Project

It’s open season for the Alaska Gasline Development Corp. That’s not to be confused with open season on AGDC, which legislators skeptical of the state-owned corporation leading and continuing the roughly $40 billion Alaska LNG Project have had on its biggest proponent, Gov. Bill Walker. AGDC’s open season to reserve pipeline and liquefaction capacity in the Alaska LNG Project started Thursday, June 15, and will run through Aug. 31, President Keith Meyer said during the corporation’s board of directors meeting, also Thursday. Potential customers interested in reserving capacity in the Alaska LNG tolling system won’t be expected to make a definitive commitment yet, Meyer stressed. But the capacity solicitation will provide pricing protection to those potential customers that do raise their hand, he said, as well as some rights to expand their share of capacity in the project and the right to have their capacity assigned to another party among other things. “We’re a little early to have a full binding open season,” Meyer said during the meeting. He also said AGDC estimates the tolling tariff will be about $6 per million British thermal units of LNG, which is nearly equivalent on an energy-cost basis to on thousand cubic of natural gas, of mcf, which is the standard unit of measurement for the commodity. Companies with interest will be expected to provide AGDC with a letter of intent to purchase capacity in the system and in-turn AGDC will respond with a term sheet specifying the foundation customer terms, including some of the aforementioned benefits. Meyer said his team has been talking with the large producers who hold rights to the North Slope natural gas that would supply the system about the process. From the state’s side, the open season will give AGDC an idea as to how much interest the market really has in the Alaska LNG Project. While there has long been ample discussion about the viability of the project — particularly since LNG prices took a worldwide dive along with oil in 2014 — it all, has been speculation to this point. According to Meyer, this is the first time the state has asked prospective customers in an LNG project to formally express interest, even if it is non-binding. Walker and Meyer have continuously said 2017 would be a year for ending that speculation and seeing if Alaska LNG could compete globally with a new financial structure since the state took the project over from BP, ConocoPhillips and ExxonMobil late last year. The crux of their position has been that the state-led project could be successful with smaller investor returns than the oil majors require while adding a major new revenue source for the State of Alaska and getting natural gas to many more communities in the state. Under the previous equity-share owner model, the producers wanted to slow down the project until the current global LNG glut subsided and prices subsequently recovered. The governor did not want the project to lose momentum after the state and the producers spent roughly $600 million studying and designing it since 2013, and took up the option for the state to take over the lead role. Also, the open season on customer solicitation will give AGDC an idea as to whether or not construction of the massive project, designed to produce up to 20 million tons of LNG per year, should be phased to match demand, Meyer said. Some pieces of infrastructure, primarily the 800-mile, 42-inch diameter pipeline, would have to be built even if the market can’t fill it right away, but the North Slope gas treatment plant and Nikiski LNG plant could start small and grow. That’s because they were designed using three “trains” to reach the 20 million tons per annum total, and those trains don’t all have to be installed at once. This round of solicitations is aimed at gaining insight into whether the producers might want to reserve capacity to sell gas into the state’s LNG tolling project. Meyer said it is still a little early in the process to expect Asian LNG buyers, many of whom he says just recently heard about the Alaska LNG Project for the first time, to step forward with a letter of intent. That’s a step Asian utilities don’t take lightly, he added. And though AGDC has been working hard to get the word out this year to spread the word about its project with Meyer making several trips to Asia, LNG customers typically don’t take the letter of intent step until at least 12 to 18 months after initial engagement from a project proponent, according to AGDC Commercial Vice President Lieza Wilcox. At the same time, Meyer said potential customers will be expected to make firm commitments by May 2018, as the customer contracts will underwrite the tens of billions of dollars of debt that will likely be needed to finance construction. To further interest from Asia, Meyer said AGDC plans to host several big LNG buyers from China this summer, but he declined to go into further detail about how many or what type of customer any of those companies might be. Elwood Brehmer can be reached at [email protected]

Marine highway supporters look for new ideas amid challenges

The M/V Tustumena is again on the disabled list for most of the season as the state nears drafting its replacement. Earlier this month the Alaska Marine Highway System announced the “Rusty Tusty,” as the state ferry is affectionately known to many, would be out of service until at least Aug. 15 after inspectors uncovered more damage to steel in the Tustumena’s engine room. The latest setback builds on the first delay of the 53-year-old ferry’s return-to-service date, which in early May was pushed back from May 27 to mid-July after the initial discovery of wasted steel in the ship’s engine room. Workers at Vigor Industrial’s Ketchikan Shipyard went to work on the Tustumena March 13 for its annual overhaul. At that time, it was expected the vessel would be back in service May 27. In 2013, unexpected repair work coupled with shipyard mistakes kept the Tustumena out of service for most of the year. It was then that state Department of Transportation officials began the process of drafting designs for the Tustumena’s replacement vessel. The Tustumena was dry docked at a shipyard in Seward at that time. The challenge the state ferry system has faced regarding the vessel is that at 296 feet it is significantly smaller than the other mainliner ferries the state operates but for several reasons, including the fact that it is the only ferry with a vehicle elevator to match the fixed docks in many of the communities the vessel serves, there aren’t other options. As a result, the relatively small, aging Tustumena has long been tasked with running the rough and tumble route between Homer, Kodiak, the Alaska Peninsula and the Aleutians, much of which is exposed to the vast Gulf of Alaska. The dock situation along the Tustumena’s route means it is more feasible to replace the Tustumena with a new vehicle elevator-equipped ferry than it is to replace all of the fixed docks with floating infrastructure, according to AMHS leaders. Previously when the Tustumena was laid up the M/V Kennicott would stand in and pick up at least some of the slack in accessible communities, as happened in 2013. This year, however, multiple years of budget cuts to the AMHS have eliminated that option. “We don’t have the funding to absorb those changes,” AMHS spokeswoman Meadow Bailey said. That means the normal 10 ferry runs through Southwest Alaska will be cut to three this year, according to AMHS — unless the Tusty is delayed yet again — with the first starting Aug. 22. Bailey added that overall ferry service has been cut 20 percent from its peak several years ago as the solely state funded AMHS budget has shrunk. She also noted that private shippers have tried to stand in for the Tustumena. Seattle-based Coastal Transportation, which operates solely between Washington and Southwest Alaska, is hauling cargo and vehicles on a space-available basis for displaced freight at AMHS rates and Samson Tug and Barge and Grant Aviation have assisted as well, Bailey said. On June 13 the AMHS announced the M/V Columbia, which runs between Southeast and Bellingham, Wash., will be at Vigor’s shipyard in Portland longer than expected for propeller repairs. The Columbia is now expected to be back in service July 26. It struck an unknown object last September and immediately went in for repairs. However, parts of the newly installed propeller system failed during sea trials and the problem is now being diagnosed, according to the ferry system. The M/V Malaspina is filling in for the Columbia, but because it is a smaller vessel, some vessel cabins and vehicle space reserved for the larger Columbia will be unavailable. The $244 million for the Tustumena replacement vessel is in the state capital budget that is tied up in the Legislature’s ongoing debate over what the State of Alaska’s long-term fiscal plan should be. The state’s cost to replace the Tustumena is $22 million, with the feds picking up the remaining $222 million tab. Because the Alaska Marine Highway System is classified as a traditional highway by the federal government, new state ferries can be built with primarily federal money by employing the 90-10 federal-state funding split that funds most highway projects across the country. However, using federal funds also means the new vessel likely won’t be built in Alaska, as any shipyard nationwide will have the ability to bid on the project. The two smaller Alaska-class “day boat” ferries currently under construction at the Ketchikan Shipyard were paid for completely with state funds, allowing state officials to make sure the state money was spent in Alaska. The Alaska-class ferries, the Tazlina and the Hubbard, are scheduled to be finished in October 2018. Bailey said the 330-foot, unnamed Tustumena replacement could be done about five years after it is funded, putting the earliest likely completion date sometime in 2023. Ferry officials have also been unsuccessful in trying to sell the one of the system’s original vessels, the 54-year-old M/V Taku. Sealed bid auctions this year with minimum bids starting at $1.5 million and then $700,000 did not attract any buyers. In 2003, the State of Alaska resorted to eBay to sell the E.L. Bartlett for $389,500, which was the last time an Alaska state ferry was sold. AMHS reform The State of Alaska and the Southeast Conference are also asking for input from AMHS stakeholders on how to best shape the long-term future of the ferries. Last year Gov. Bill Walker signed an agreement with the Southeast Conference to collectively examine reforming the Alaska Marine Highway System into a more efficient and financially stable operation. The Southeast Conference is Southeast Alaska’s nonprofit regional development organization. Currently run as a division of the Alaska Department of Transportation and Public Facilities, the AMHS is funded through annual legislative appropriations. This regularly makes it subject to political funding battles between legislators from smaller coastal communities and those from the rest of Alaska who are highly critical of the AMHS because it is not self-sustaining financially. Phase One of the reform study, finished in December, examined the organizational structure of other ferry operations and recommended the AMHS be morphed into a public corporation to, as much as possible, eliminate politics from leadership and decision-making. The study also concluded the ferry system should have a dedicated funding stream to help stabilize service levels. That in turn would allow ferry schedules to be set further in advance than the several months ahead of schedule they are set now. More reliable scheduling would likely increase ridership, according to the study, particularly from tourists who often book trips a year or more in advance. Phase Two is examining a 25-year operating plant that includes looking at funding options, possible partnerships with the private sector and a fleet renewal plan in more detail and should be done late this fall.

Innovation targeted at teacher turnover, remediation

The leaders of Southcentral school districts and a nationally renowned University of Alaska Anchorage program are blending high school and college in an attempt to cure the state of multiple education ills. The Anchorage School District recently took over the Alaska Middle College from the Matanuska-Susitna Borough School District, which is expanding the program in its own territory. Given the classes are held at UAA’s Eagle River campus, it made sense for Anchorage School District students to attend and allow Mat-Su students to utilize a similar opportunity closer to home, ASD Administrative Projects Director Kathy Moffitt said. Moffitt first worked on the Alaska Middle College with the Mat-Su District before transitioning to Anchorage. Over at UAA’s main campus, Alaska Native Science and Engineering Program founder Herb Schroeder is expanding his wildly successful efforts to grow more young Alaskan engineers and scientists to include building “a cadre of Alaskan teachers,” Schroeder said. “We need Alaskan teachers, people who love this place, people who will always be here no matter what,” he said. Moffitt and Schroeder spoke during a June 13 luncheon in Anchorage hosted by the local public policy think tank Commonwealth North. The work both are doing is aimed at conquering major issues in Alaska’s K-12 education system from the ground up. It’s based on the presumption that more prepared students will make better teachers who improve what are currently less-than-stellar student performance metrics. According to Schroeder, 60 percent of University of Alaska freshman coming from the 37 largest high schools in the state over the past decade have needed remedial math or English courses. At the lowest performing high schools, the remediation rate is nearly 75 percent of college-bound students, who have an average high school GPA of 3.16, he said. That means many of the students who qualify for the state Performance Scholarship don’t have the skills to jump into college. Annually, about 1,000 students arrive at a UA campus in need of remedial education, Schroeder said. “Imagine being on the honor roll and an academic hero with scholarships to prove how awesome you are and you find out that you are a year or more in some cases behind where you thought you were,” he described. “It’s an esteem-shattering gut punch. Financially, it can be devastating for families.” Adding a year of remedial classes — that don’t count towards college credits — collectively costs the families of those students about $24 million each year in extra tuition, books and room and board expenses. It also costs the state another $18 million per year given its support of the university budget, according to Schroeder. Finally, because the state is the primary funder of K-12 education and 70 percent of the students in need of remediation passed high school classes that should have prevented that need, “the state’s paying twice,” he said, while at the same time trying to fill a $2.5 billion budget shortfall. “Right now that whole $42 million is being spent (by families and the state on remedial classes) trying to repair the damage that was done over the previous 12 years and what I want to do is to take a portion of that money and reinvest it earlier so that we don’t have to repair that damage,” Schroeder said. Alaska Middle College has quietly been providing high school students the opportunity to earn high school and college credits at the same time for five years. In the school’s last graduating class, 13 students took an associate’s degree home along with their high school diploma, according to Moffitt. “Students test into college just as any student would and they attend classes with other college students,” she said. Available to high school juniors and seniors, Alaska Middle College is a way to support the students through what is ostensibly their first year of college, which is usually the most difficult, Moffitt said. It’s a way to ease the transition from high school to adulthood — and it’s free to students and their families. “The power behind the program is the opportunity,” she said. Alaska Middle College is mostly aimed at getting students a head start on general education college courses, but is also developing a career and technical education, or CTE pathway focused on preparing students to become teachers. The four-course startup program is awaiting accreditation to make it college-credit eligible, Moffitt said, and the district wants to install it in Anchorage’s East High School next year. The Alaska Middle College students are placed in K-12 classrooms to mostly to observe teaching methods and student-teacher interactions from a different viewpoint the first year. In year two they “become active contributors and teachers working with students,” Moffitt said. The education-focused program came out of the University of Alaska Fairbanks’ K-12 outreach program, she added. Schroeder stresses a need for quality control and consistency in what is being taught in high school classrooms to match what the university needs students to know. Many, including him, believe the problem is directly linked to high teacher turnover across the state. According to the UAA Institute of Social and Economic Research, teacher turnover averages about 20 percent statewide and costs the state about another $20 million each year. Given the four largest school districts are generally below 10 percent turnover, many rural districts are watching upwards of 40 percent of their teachers leave each summer without coming back. Additionally, each year Alaska school districts hire about 1,000 teachers, while the state’s postsecondary schools produce only about 200 teachers per year, according to ISER. High teacher turnover — often due to the culture shock of moving from the Lower 48 to remote parts of Alaska — leads to teachers that don’t understand the unique needs of their students and apathy amongst teachers who decide quickly they will be leaving at the end of the year, among other problems, state education officials acknowledge. So Schroeder is trying to produce more homegrown teachers who know about and are excited about living and working in rural Alaska. He is working to start another of ANSEP’s full-time Acceleration High Schools in Anchorage in 2018. Classes in a summer version of the Acceleration school are going on now at UAA and ANSEP has another Acceleration program in the Mat-Su. ANSEP is open to all Alaska middle and high school students. “Many rural students want to live in villages and teaching is one of the few employment opportunities available there and the Acceleration High Schools provide the opportunity to complete much of the degree before students ever arrive at the university,” he said. Classes at Acceleration schools are taught by university faculty with support from K-12 teachers and— similar to the Alaska Middle College — students earn dual credits that can be applied to biology, engineering, business, education and other degrees. The schools are predicated on experiential learning and getting students excited about their work and their future, which Schroeder emphasizes is the most basic key to improving classroom performance. Acceleration students are also regularly mentored by peers and university students, which has helped many ANSEP students discover a love of teaching, Schroeder said. “We’re developing these schools now and success is going to require a new look at how we do education. Nibbling around the edges is not going to get us where we need to go,” he said. Elwood Brehmer can be reached at [email protected]

Eni files plan to explore federal Arctic OCS leases

Italian oil major Eni Petroleum is preparing to drill four exploration wells into offshore federal territory from its manmade North Slope island in state waters. If approved by the federal Bureau of Ocean Energy Management, the work program would take 18 months, according to the proposed work plan Eni submitted to the agency. The work would start with the drilling of the first well in December and end when the flow test of the final well is complete in May of 2019. Eni is the sole owner and operator of the Nikaitchuq unit in state waters just offshore from the large Kuparuk River field. Drilling in the Nikaitchuq unit is conducted from the manmade Spy Island, which sits roughly in the center of the unit and is about halfway between the shore and the three-mile boundary that delineates near shore state and offshore federal waters. The company has produced between 20,000 and 22,0000 barrels of oil per day from Spy Island in recent months. In late February BOEM approved the Harrison Bay unit, which is comprised of 13 federal outer continental shelf leases. Specifically, Eni is proposing to drill two main wellbores, each with a lateral sidetrack, from Spy Island that will reach seaward into the company’s federal Harrison Bay leases. The first main bore well would be drilled and tested from December through March 2018. That would be followed by the drilling and flow testing of a sidetrack next spring as well. The second set of wells would similarly be drilled and tested the following fall to spring. Eni is planning to drill the main wells to depths of about 7,500 feet and 8,300 feet with the offshoots extending more than 20,000 feet to reach the targeted areas in the federal leases. The drilling will be done with Doyon Drilling’s Rig 15, which is capable of drilling on an eight-foot well spacing pattern on the space-constrained gravel island, according to Eni’s exploration plan. Spy Island has space for 36 producer and injector wells. It currently has 31 production and injection wells and one disposal well, according to Eni. BOEM is soliciting public comments on Eni’s exploration drilling plan through July 3. Elwood Brehmer can be reached at [email protected]

Oil prices, policy uncertainty prompt Caelus to postpone well

Caelus Energy won’t be drilling new wells on the North Slope next winter for a host of reasons. As a result, Alaskans will have to wait at least another year to see whether the company’s promising but remote Smith Bay oil prospect, which Caelus leaders have touted to be a 6 billion-barrel discovery, lives up to its billing. The company had planned to drill a production-like appraisal well at Smith Bay in early 2018 to prove up what its two early 2016 exploration wells and detailed 3-D seismic data indicated — that Smith Bay could produce upwards of 200,000 barrels of oil per day. However, Caelus spokesman Casey Sullivan said in an interview that the company wants to advance Smith Bay as quickly as it can but “lower for longer” oil prices and the continued dismantling — on a couple of levels — of the state’s oil and gas tax credit program are impeding progress. Smith Bay is a very remote prospect about 125 miles northwest of existing central-Slope oil infrastructure and about 70 miles east of Barrow. While its location, size and the unavoidable long-term nature of North Slope projects means development will assuredly take at least five years or more and ostensibly makes current oil prices meaningless for Smith Bay’s commercial viability, prices have impacted revenue from Caelus’ Oooguruk development, the company’s only sustained revenue source. Smith Bay’s location makes even a small winter drilling program a $100 million-plus venture, according to Sullivan. And despite indications for months that there was bipartisan agreement in the Legislature, with support from Gov. Bill Walker, to end the cashable tax credit program on the North Slope, Sullivan said House Bill 111 did impact the decision to delay drilling again at Smith Bay. “Any prudent investor, any prudent company will take pause and make sure we understand what the next layer of rules might be before we make significant investments,” he said. The final version of HB 111 is currently being debated in the Legislature. Both the House and Senate versions of the bill cut refundable oil tax credits from state law Jan. 1, 2018, just before Caelus would have drilled the Smith Bay well. While the Senates bill does little else, the Democrat-sponsored House legislation would also increase taxes on the state’s large producing fields and restrict how companies can utilize future production tax deductions. Last November Caelus Energy Senior Vice President Pat Foley said at a Resource Development Council of Alaska conference that the company had been told on no uncertain terms that “the ongoing liability that’s created by the refundable tax credits is just not sustainable by the state.” In the same speech Foley said Caelus was planning to drill an appraisal well at its prized prospect and hoped to drill two exploration wells on state acreage it holds east of Prudhoe Bay in early 2018. Sullivan said at this point Caelus doesn’t have work planned for its eastern Slope holdings anymore, either. Caelus has also applied for roughly $200 million in tax credit certificates, more than $100 million of which are past due for payment from the state due to Walker’s vetoes of $630 million in credit payments since 2015, according to Sullivan. Walker vetoed the tax credit payments — and drew sharp criticism from Republican legislators and the oil industry for it — contending the state could not afford to pay down the obligation while continually battling $3 billion budget deficits without a long-term fiscal plan. Additionally, Sullivan said low oil prices and activity elsewhere have made rounding up private support all the more challenging these days. “We believe, based on our science, that there’s more than 6 billion barrels in place (at Smith Bay), but it still takes money to get out there and prove up that resource and again there’s intense competition for that capital currently under the price environment and under what we’re seeing happen in the Lower 48, particularly in the (Texas) Permian basin, where you have the ability to — I’d leave it at there’s intense competition for capital,” he said. Caelus, a small independent, receives significant funding from Apollo Global Management LLC, a New York-based private equity investment firm along with financing through debt from other lenders, according to company leaders. Some state officials and independent industry representatives have noted Caelus’ tight oil find at Smith Bay is unequivocally encouraging, while at the same time trying to temper optimism about it, saying it is far from proven absent a flow test from an appraisal well. And if Smith Bay in fact is as large as Caelus purports, full development would still require leaping a series of regulatory and economic hurdles given its remoteness and location adjacent to the federally owned National Petroleum Reserve-Alaska, which any access road or pipeline would likely have to cross. As for what Caelus already has in production, the company is undertaking a well workover program to get the most oil it can out of its small Oooguruk field. “It’s a multimillion-dollar investment to go back in and hope to optimize production from some of the wells we’ve already drilled,” Sullivan described. Caelus stopped drilling at Oooguruk for the first time in seven years last spring when sustained low oil prices and the issues with the state’s tax credit payments made new investment challenging, company leaders said. Oooguruk is currently producing about 15,000 barrels of oil per day. According to Foley about 40 wells have been drilled at Oooguruk and Caelus wants to drill another eight. The company also holds the sanctioned-but-suspended Nuna project on the North Slope, which with about $1 billion of capital could start producing in two years and peak at about 20,000 barrels per day whenever North Slope oil economics improve. “We’re still super bullish on Alaska and we’re ready — as soon as we get some stability in price and policy — we’re ready to get moving forward again,” Sullivan said. Elwood Brehmer can be reached at [email protected]

Final Railbelt electric plan cost estimate nears $900M

The Alaska Energy Authority is sticking with its belief that one of the state’s most critical pieces of infrastructure needs close to $900 million of improvements to truly be both reliable and efficient. AEA’s final Railbelt Transmission Plan completed this spring concludes there are $885 million worth of projects to improve the economics and reliability of the electric grid from the southern Kenai Peninsula to Fairbanks. Another $54 million of work to add substations and transmission lines primarily around Anchorage would improve system reliability but not significantly improve the economics of the Railbelt electric grid, according to AEA. The Railbelt Transmission Plan was compiled for AEA by the Anchorage-based consulting firm Electric Power Systems Inc. A draft version of the study released in early 2014 estimated the need to be $903 million, but that included some smaller projects to integrate the now-suspended Susitna-Watana hydropower project into the region’s transmission system, AEA Chief Operating Officer Kirk Warren said during the authority’s May board meeting. Warren said about $400 million of the total estimate is for projects aimed at improving the flow of power from the 120-megawatt, AEA-owned Bradley Lake hydropower plant near Homer to the demand centers of Anchorage, the Mat-Su and Fairbanks. However, leaders of the six Railbelt electric utilities have to varying degrees dismissed AEA’s assertions that all of the transmission upgrades — with a steep collective price tag — are necessary. They contend a smaller, more targeted work plan could provide improved efficiency with far less cost. Matanuska Electric Association officials have said upgrading capacity of the southern Railbelt transmission intertie between the Kenai Peninsula and Anchorage could be done for as little as $50 million without the expensive reliability improvements that many in the utilities believe are unnecessary. While there is disagreement over how much should be spent, there seems to be consensus among the key players that improving access to Bradley Lake power is imperative. The current Kenai Peninsula transmission system, which is a single line between Soldotna and Anchorage, limits the availability of Bradley power when the hydro plant is operated at above 65 megawatts, or just more than half of its capacity. The oldest part of the line was built originally in 1961 to move power from the small Cooper Lake hydro plant near Cooper Landing to Anchorage, according to the study. It’s the inability to maximize the use of Bradley Lake whenever the utilities want it — at about 4 cents per kilowatt-hour, the hydro plant is the cheapest power source in the region — that limits its usefulness. Additionally, AEA is pursuing a $50 million project to divert part of nearby Battle Creek into the Bradley Lake system, which would increase Bradley’s generation capacity by about 10 percent. Specifically to combat the transmission line constraints and improve system reliability, AEA is proposing to run a new, subsea 100-megawatt, high-voltage direct current, or HVDC, line between Nikiski and Chugach Electric Association’s Beluga power plant on the west side of Cook Inlet. That standalone project is estimated at $185 million. The cross-Inlet HVDC line improves reliability, but doesn’t completely free Bradley Lake power because the hydro plant would still have to be operated at a level that the existing intertie could handle in the event the subsea line was lost, according to the transmission plan. As a result, more than $100 million in additional capacity upgrades to the existing transmission lines on the northern Kenai Peninsula, as well as a new, $66.6 million 115-kilovolt line between Soldotna and Bradley Lake are recommended. The system redundancy created by the new subsea line could also allow spinning reserve, or backup, generation plants on the Peninsula to be shut down. That could then save money for Peninsula ratepayers who would not have to support the full cost of their own backup generators if today’s line to Anchorage were lost or any reason, Warren said. The southern intertie has been out of service for almost a month each year over the past decade, according to the study. The lack of extra transmission capacity is also a direct impediment to new renewable energy projects, the study also notes. A similar scenario with added spinning reserve costs plays out in Fairbanks, as much of the northern electric intertie between Willow and Healy is a single transmission line, too. For the northern half of the Railbelt, AEA suggests a new 230-kilovolt line between Point MacKenzie and Willow at a cost of $128 million and another new $245 million line between Willow and Healy, which would de-constrain and add redundancy to the northern transmission lines. AEA owns the northern intertie, which was built in the mid-1980s with direct state appropriations. The second transmission line between the Interior and Southcentral “will prevent the loss of load in Fairbanks for single line outages and will allow (Golden Valley Electric Association) to access electrical and gas markets in the Southcentral system,” the transmission plan states. “It will also allow GVEA to evaluate the most economic solution for replacement generation capacity as its power production fleet continues to age or if coal resources are retired.” AEA estimates the suite of projects — forecasted in 2030 dollars, when the work could be completed — would save Railbelt consumers between nearly $35 million and $83 million collectively on their electric bills each year strictly through allowing utilities to always use the cheapest power source and the potential to optimize spinning reserve Railbelt-wide. The earlier draft of the transmission plan had much greater estimated savings, between about $80 million and $240 million per year, because it made assumptions that the utilities would minimize or eliminate their spinning reserve once redundancy was built into the transmission system, according to AEA’s Warren. However, he said the final study focused on the most economic dispatch of power because each utility has its own requirements for back-up generation. “Without additional transmission improvements, generation planning will continue to be completed by individual utilities, located in geographically dispersed areas,” The study concludes. “Capacity sharing and deferral will be limited by the existing transmission system and customer rates will not be at their lowest level possible.” As is often the case, one of the biggest hurdles is determining who pays for what, particularly given the fact the State of Alaska won’t be offering the grant funds that have covered these types of infrastructure projects in the past. The utilities could debt finance the projects themselves, Warren said, but that is quickly complicated by several factors. “The real issue revolves around settlement amongst the utilities on who pays for what,” he said. Partially because ownership of the transmission lines is fragmented to each utility’s service area, a utility that owns a segment of transmission and thus is on the hook for it may not be the entity to benefit from an upgrade or new line altogether — therefore eliminating the willingness to invest. For example, Golden Valley Electric’s Interior ratepayers would undoubtedly see the benefits of more transmission capacity in Anchorage and the Mat-Su area to allow additional lower cost and cleaner natural gas-fired and renewable-sourced power to flow north. But absent complex agreements to pay for the upgrades, the Southcentral utilities would have to pass along the costs of the transmission work to their ratepayers while most of the benefits would likely be realized elsewhere. To that end, the utilities have been working with American Transmission Co., a Milwaukee-based transmission-only utility that has been pitching the idea of forming a Railbelt transmission company, or TRANSCO, for nearly two years, which the utilities could become member-owners of. Ideally, the TRANSCO would be a vehicle for the utilities to collectively finance the major transmission investments; it could also set a flat, Railbelt-wide transmission tariff to encourage more selling of the most economic power amongst the utilities. Currently, each utility adds its own tariff to power that travels across its lines, challenging the economics of moving power across multiple transmission jurisdictions. Warren said AEA, as a transmission asset owner itself, has an interest in how the TRANSCO talks shake out and the utilities — each with their own transmission and generation profiles and internal requirements — “are all over the place.” Elwood Brehmer can be reached at [email protected]

No repeat of Prudhoe standoff as state approves 2017 plan

State Department of Natural Resources officials have approved BP’s work plan for the Prudhoe Bay oil and gas field without issue, a year after state demands for new information led to a summer-long standoff over the annual report. Division of Oil and Gas Director Chantal Walsh approved the 2017 Prudhoe Bay Plan of Development May 25 in a letter to BP Alaska management. This year’s Prudhoe POD contains sufficient information about BP’s efforts to support a project to commercialize North Slope natural gas reserves — and those of its fellow Prudhoe Bay working interest owners ConocoPhillips and ExxonMobil —that the plan was approved on a normal schedule, according to Walsh. Resistance to state demands for natural gas development and marketing information last year led to the plan approval being delayed until early September. BP submitted the development plan to the Division of Oil and Gas March 30. It takes effect July 1 and covers the drilling and major maintenance activities planned for the field in the coming year as well as reviews the prior year’s work. The 2017 plan outlines several engineering studies BP conducted in preparation for the Alaska LNG Project, which Gov. Bill Walker’s administration is pushing to have ready to pipe gas off the Slope in the mid-2020s. It also notes the company responded to more than 145 requests for information related to the Alaska LNG Project last year. For the coming year, the plan states BP expects information the requests to continue; now they will be coming from the state-owned Alaska Gasline Development Corp., which officially took control of the project from the consortium of producer companies last December. BP has offered a draft confidentiality agreement to AGDC so it can more easily share potentially sensitive technical and commercial data with the state-owned corporation to everyone’s satisfaction, according to the 2017 Prudhoe POD. Containing about 28 trillion cubic feet of natural gas, the Prudhoe Bay field has more than three-fourths of the known North Slope gas reserves that the Alaska LNG Project, or any other gas commercialization effort, would draw from. In the interim, BP will continue using the gas to enhance oil production. The company estimates that reinjecting the natural gas that comes to the surface with oil and repressurizing the reservoir supports approximately 40 percent of current oil production. In January, BP and the Alaska Gasline Development Corp. also signed a one-year agreement under which the producer will assist the state corporation in securing financing and customer contracts to support the roughly $40 billion Alaska LNG Project. In January 2016, then-DNR Commissioner Mark Myers sent a letter to all oil and gas unit operators informing them state officials would be requesting new information about efforts to market and develop natural gas resources for either in-state or Outside uses, depending on the field and situation. BP’s 2016 Prudhoe POD, submitted in late March of that year, included two brief and generic paragraphs about developing natural gas from the field. It stated that “major gas sales” from Prudhoe depend on many market variables and until a viable project is sanctioned the company and its field partners would continue to use the gas to maximize oil recovery. The 2016 POD was quickly deemed incomplete by top DNR officials, while BP, ConocoPhillips and ExxonMobil contended the new demands broke from longstanding regulatory precedent. That resulted in a summer-long schism between the producers and the Walker administration and an extension of the 2015 POD as the effective operating document. The conflict ended in September when BP and ConocoPhillips sent a joint letter to Walker announcing their support of a state-led Alaska LNG Project. DNR Commissioner Andy Mack also wrote in the approval letter to BP that the working interest owners would be expected to detail their activities to support major gas sales in upcoming Prudhoe PODs. On the oil side, BP is projecting oil production will be flat to down 40,000 barrels per day from the 197,900 barrels per day of oil and natural gas liquids the company extracted from Prudhoe Bay in 2016. The company made an identical prediction for production in last year’s POD, but ended up with a slight but unexpected increase in production over 2015. ^ Elwood Brehmer can be reached at [email protected]

Judge in LIO case denies owners’ request to enter new evidence

A request for new evidentiary hearings in the $37 million lawsuit brought by the owners of the now-vacant Downtown Anchorage legislative information office against the Alaska Legislature was shot down in a Wednesday state Superior Court ruling. Judge Mark Rindner’s order means the case will likely be decided on the facts already presented — and was a win for legislators. 716 West Fourth Avenue LLC, the building owner group comprised of Anchorage real estate developers, appealed its $37 million contract claim to the Superior Court last December after then Legislative Council chair Sen. Gary Stevens denied the claim last fall. The full, 14-member council subsequently denied 716’s appeal of Stevens’ decision without a hearing. The Legislative Council — the actual defendant in the suit — handles business matters for the full Legislature. Attorney for 716 Jeffrey Feldman argued before Rindner in a May 19 hearing on the matter that Stevens relied heavily on “hearsay” evidence such as newspaper articles to support his decision and largely ignored supporting materials submitted by the developers. According to Feldman, an allowance for new evidence in the case would expose the fact that legislators shirked their responsibilities to act in good faith and uphold the 2013 deal that had 716 invest $37 million in the $44.5 million on the premise the Legislature would occupy the building long-term. The Legislature contributed the remaining $7.5 million. Instead, legislators bowed to political pressure from constituents who were unhappy with the 10-year, $3.3 million per year lease they signed for the space built just for them and backed out of the deal without compensating his clients, Feldman contended. In his order Wednesday order, Rindner wrote that allowing an evidentiary hearing, or trial de novo, would be outside the norm procedurally for an administrative appeal such as 716’s claim and that “there are significant questions of law that must be resolved before any additional findings of fact are made.” Rindner said during the May 19 hearing that it shouldn’t be a surprise that legislators make decisions for political reasons and expressed hesitancy towards a court-ordered exposure of why they ultimately decided to leave the building, saying the court could very quickly be blurring the separation of powers between the branches of government. If and when the legal questions are answered, Rindner can then decide if further discovery is needed, at which point the case could be remanded back to Legislative Council to unearth new evidence, which would be normal procedure, he wrote further. He did not elaborate on which legal issues are unresolved, but concluded with, “Proceeding in this way will allow remaining factual issues, if any, to be more narrowly defined.” Legislative Council is now chaired by Juneau Rep. Sam Kito, who repeatedly advised against the Legislature walking away from its Anchorage offices on the belief doing so would invite such a lawsuit. Elwood Brehmer can be reached at [email protected]

Zinke orders new looks at Arctic oil development

It’s safe to say the Alaska Oil and Gas Association won the day Wednesday. Not only did new Interior Secretary Ryan Zinke deliver the keynote address at the association’s annual conference, he signed a secretarial order directing Interior agencies to review management and leasing of the North Slope National Petroleum Reserve-Alaska and conduct a new oil and gas resource assessment of the Arctic National Wildlife Refuge coastal plain. According to Zinke, it is believed to be the first secretarial order signed in Alaska. During a press conference following his speech, Zinke questioned the rationale of the decision by President Barack Obama’s administration to make roughly half of the 22 million-acre NPR-A off limits to oil and gas leasing. “In military terms it’s almost been a delaying, rear-guard action over the past administration,” Zinke said. “When you look at the area that was off limits in the National Petroleum Reserve — arguably the most productive areas.” Interior’s 2013 Integrated Activity Plan for the NPR-A, which is the Bureau of Land Management’s plan for how to manage the area, prohibited leasing in much of the northeast portion of the reserve that is closest to existing Slope oil infrastructure. That area also contains Teshepuk Lake, a massive breeding ground for waterfowl and caribou. The 2013 NPR-A plan potentially kept 350 million barrels of recoverable oil and 45 trillion cubic feet of natural gas away from development, according to Interior estimates. In 2010, when oil prices were about twice what they are today, the U.S. Geological Survey estimated the NPR-A held nearly 900 million barrels of economically recoverable oil. In January, ConocoPhillips announced that it believes its Willow discovery on the eastern edge of the NPR-A holds 300 million recoverable barrels of oil. The ever-controversial Arctic National Wildlife Refuge — on the other side of the North Slope from NPR-A — could hold upwards of 10 billion barrels of oil, with more than 7.6 billion barrels in the 1002 coastal plain area, according to a 1998 USGS evaluation. The 1.5 million-acre 1002 Section of the 19 million-acre refuge was carved out by Congress in 1980 and left open to the prospect of petroleum development because of that potential. To date, one well — the results of which are still confidential — has been drilled into the ANWR coastal plain in 1985. A 2-D seismic survey was also conducted in the 1980s and is the main source of information about its oil potential. Zinke referenced President Donald Trump’s directive to him to make America “energy dominant” time and again during his five days in Alaska and it was a frequently used phrase Wednesday. “Energy dominance can’t happen unless Alaska is a partner,” Zinke said. Gov. Bill Walker, who has long pushed for exploring ANWR, compared the significance of Zinke’s action today to Vice President Spiro Agnew’s 1973 tiebreaking vote in the Senate in favor of constructing the trans-Alaska pipeline. “This is a day we have waited for for a long time,” Walker said. While the impact of Zinke’s order almost assuredly won’t be as immediate, the excitement among resource development advocates at the AOGA conference couldn’t be oversold. “The attitude of partnering…We had to play defense for so long we forgot what offense is like and now we’re going to be able to work in partnership (with the federal administration),” Walker said, referencing land management battles with the Obama administration. The ANWR coastal plain assessment will be done by federal and likely state geologists and Zinke said he wants to include industry as well to continue fostering the partnership mentality he is working to instill across his department. Today’s 3-D seismic technology should also provide a much better resource estimate than what was capable in prior exploration. In 2013, former Gov. Sean Parnell and then-Alaska Department of Natural Resources Commissioner turned U.S. Sen. Dan Sullivan submitted an ANWR Section 1002 exploration plan to the Interior Department that estimated a winter seismic shoot would cost approximately $50 million. Regardless of what is found, opening the ANWR coastal plain to development and oil production requires congressional approval, which is still a long ways off. “It’s hard to make decisions unless you know what’s there, so we’re giving the green light to do the (ANWR) assessment,” Zinke said. And on the day he signed the order, The Wilderness Society released an update to its report against oil activity in ANWR entitled, “Too Wild to Drill.” Zinke, who in his address to AOGA described himself as a “Teddy Roosevelt Republican,” said he strongly supports the National Environmental Policy Act, which prescribes the process to evaluate large development projects across the U.S. However, he stressed NEPA should not be used to manipulate conservation or development decisions, as Republicans have regularly accused the Obama administration of doing. “Nothing I signed today skirts NEPA,” Zinke said. “Nothing I signed today diminishes or relaxes environmental protections that are necessary.” Elwood Brehmer can be reached at [email protected]

Matson completes sulfur-scrubbing exhaust upgrades

Much of what Alaskans buy locally is now getting here on cleaner ships. Pacific shipper Matson Inc. announced in May that its containership, the Matson Anchorage, is now outfitted with a “wet scrubber” system aimed at eliminating sulfur emissions from the ship’s exhaust. The Matson Anchorage was the last of the company’s three Alaska-dedicated vessels to get the exhaust scrubbers. The Matson Kodiak and Tacoma were outfitted with the system last year. Honolulu-based Matson President Ron Forest said in a formal statement that the company consulted heavily with the U.S. Coast Guard and the Environmental Protection Agency to get the unique exhaust scrubber system approved. “Our hybrid system is new, so it has required extensive testing and independent analysis to earn federal certification,” Forest said. “The Coast Guard and the EPA have been enthusiastic about the environmental benefits and worked closely with our engineers to develop and certify our new system. It has become a good example of public-private sector partnership in bringing environmental innovation to the marketplace.” Matson Alaska Vice President Ken Gill described the system in an interview as one that “washes the emissions” out of the vessels’ diesel exhaust. The closed-loop scrubber system works by spraying a fresh water-sodium hydroxide solution into a ship’s exhaust system. The water is then collected and stored for shore side disposal and treatment. An extremely alkaline, or basic, compound, sodium hydroxide is the primary component of lye, a fundamental ingredient in many soaps. When put in contact with sulfur dioxide found in diesel exhaust it bonds to the sulfur and prevents it from being emitted into the atmosphere. “We pump a tremendous amount of water up these (exhaust) stacks. It’s really tremendous technology,” Gill described. The exhaust scrubbers are Matson’s way of complying with the international Emission Control Area, or ECA, standards. Approved as an amendment to the U.N. treaty Marpol in 2010, ECA standards require ships operating within 200 miles of the U.S. or Canadian coasts to use fuel containing less than 0.1 percent sulfur by 2015. A 1 percent sulfur limit on fuel took effect in August 2012. The control area was instituted as a way to improve air quality in U.S. and Canadian ports. EPA projects the tighter emissions standards will reduce sulfur emissions by 920,000 tons before 2020. While simply buying the ultra-low sulfur — and more expensive — diesel fuel was an option to comply with the ECA, many large vessel operators chose alternative routes to lower their sulfur output. Those working to comply with the emissions standards long-term were granted waivers to the 2015 deadline so modifications could be made to vessels without impacting scheduled freight or passenger traffic. Matson’s fellow Washington-to-Alaska scheduled shipper Tote Maritime chose to convert its roll-on roll-off vessels from diesel to LNG starting in 2015. Cruise industry giant Carnival Corp., which operates Princess Cruises and Holland America Line in Alaska, announced in 2013 it would install exhaust scrubbers similar to those used by Matson. Matson employs the scrubbers when its vessels are operating within 12 miles of the coastline, according to a company release. Matson Inc. purchased Horizon Lines Inc.’s Alaska business for $469 million in 2015 to enter the Alaska market. Then, in August of last year Matson announced the acquisition of another shipping company, Span Alaska, for $197 million in cash. Counting the exhaust upgrades, Matson has spent about $50 million on improvements and equipment in its Alaska operation since purchasing Horizon. ^ Elwood Brehmer can be reached at [email protected]

Zinke: Role for Alaska in US ‘energy dominance’

Secretary of the Interior Ryan Zinke hasn’t been in Alaska long, but he’s got one of the state’s unofficial mottos down. “Fill the pipeline,” he said during a May 30 press conference in Anchorage. “The president has said ‘energy dominance,’ and the only way that energy dominance is possible is through the great state of Alaska,” Zinke continued. Formerly a Republican congressman from Montana, he stressed a desire to “reorganize” the Department of the Interior and rebuild how the agency responsible for managing the vast majority of federal land in the country interacts with state and tribal governments. “My biggest priority is trust,” he said. “As a steward of our greatest lands, I want to ensure that we are trusted not only by the citizens of the United States, by the Native villages, but also by industry. That we’re fair, that we’re transparent. That the permitting process is done by (National Environmental Policy Act guidelines), but it’s not arbitrary.” Zinke likened his view of how he wants Interior agencies to work with states, tribal governments and even other federal departments at a high level, to the collaboration seen in how they all collaborate to fight forest fires. In fighting large fires, federal agencies regularly share funds and personnel across departments to prioritize funds and similar efforts are made to support state responders. He began his tour of the North with stops in Norway and Greenland led by Sen. Lisa Murkowski before arriving in Alaska over the weekend. In the state he visited Prudhoe Bay before spending Memorial Day at Denali National Park prior to the May 30 meetings with Alaska Interior Department Employees and Native leaders. He was also scheduled to give the keynote address at the Alaska Oil and Gas Association’s annual conference May 31 in Anchorage. Zinke sounded the right notes for Alaska’s all-Republican congressional delegation that sparred with former President Barack Obama and his Interior Secretary Sally Jewell on nearly every issue — aside from renaming Mt. McKinley to Denali, of course. “We clearly, in my view, have a secretary of the Interior, who’s a partner in progress, an advocate, not an adversary, and I think that’s the most important thing we’re going to see with this secretary,” Sen. Dan Sullivan said. Gov. Bill Walker, who generally sided with the federal delegation in pushing back against the former administration’s actions to slow or outright prohibit oil and gas development on federal North Slope lands and Arctic offshore waters, said in a May 26 statement from his office that he is excited to discuss Alaska’s role in furthering domestic energy production. “I had three meetings with the secretary in Washington, D.C., and look forward to continuing our productive conversations while hosting him in our beautiful state,” Walker said. “Secretary Zinke will see first-hand that Alaskans are committed to responsible resource development.” With budget fights omnipresent in the Capitol and the White House, Zinke noted how offshore oil and gas revenue — from the Arctic or otherwise — could be put to use within his department. In 2008, the feds collected approximately $18 billion in offshore revenue, a total that dropped to about $2.6 billion last year, according to Zinke. He acknowledged that some of the decline was due to lower oil prices leading to less royalty revenue, but said that certainly didn’t account for all or even most of the roughly $15 billion drop in annual federal offshore resource revenue in less than a decade. “Industry didn’t view us with the trust that’s needed to invest,” Zinke said. Had that revenue stream been maintained, just one year’s worth would have covered the more than $11 billion of deferred maintenance the National Park Service is trying to manage, he contended. Inviting industry investment does not mean shirking a commitment to the environment, he said as well. “I’m a Boy Scout. I believe you should leave your campground in better or the same condition that you found it, but when our regulatory framework is uncertain, is arbitrary, that along the way obstacles, sometimes intentionally, have been put in place — industry needs a signal that we’re good partners with them,” Zinke said. His press availability was held at Cook Inlet Region Inc.’s Anchorage headquarters just after he and the delegation heard from Alaska Federation of Natives leaders. He said a large part of revamping how the Interior Department operates will be increasing the role tribal governments play in decisions about federal lands and fish and game management on them. “The (Native) villages are not monolithic. They have different cultures, sometimes different languages and aspirations. I think we need to be not so monolithic in our approach, but be more collaborative at the village level, in some instances,” Zinke said. “I’ve always said, the triad of sovereignty, self-determination and respect.” He mentioned the possibility of government-to-government compacts with Native Tribes on issues of resource management and development that impact them. “I didn’t hear a whole lot upstairs about not wanting to use the resources, about not wanting to go forward and making sure that villages are economically viable,” Zinke said of his meeting with AFN leaders. “I want to make sure sovereignty is more than a word; it’s done with action.” Zinke also recently named Steve Wackowski, formerly of the Anchorage-based oilfield services company Fairweather Science and a campaign official for Sen. Lisa Murkowski’s 2016 reelection, as his senior advisor for Alaska affairs. Wackowski said Zinke made his wishes clear when he was appointed. “The big marching orders were: fill the pipeline,” Wackowski said. ^ Elwood Brehmer can be reached at [email protected]

State regulators hit Ahtna with $380K fine for gas well violations

(Editor's note: This story has been updated to inlcude new information in a June 1 statement from Ahtna Inc.)   An Ahtna Inc. subsidiary has racked up $380,000 in fines from the Alaska Oil and Gas Conservation Commission for allegedly ignoring mandates to monitor and report the conditions of a natural gas exploration well it drilled last year. The commission issued the fine to Tolsona Oil and Gas Exploration LLC because the drilling company, among other things, repeatedly failed to provide data on the natural gas exploration well the company drilled last fall and was not responsive to efforts by commission officials to contact the company, according to a May 24 AOGCC order. The fine order followed an April 11 Notice of Proposed Enforcement Action that claimed Tolsona failed to hold up its end of a deal after the commission granted the company’s request to suspend the well it had challenges drilling. The Alaska Oil and Gas Conservation Commission is a technical state regulatory body responsible for oversight of subsurface oil and gas activity. Late last September the wholly owned Ahtna Inc. subsidiary spudded the Tolsona-1 gas exploration well on state land about 11 miles west of Glennallen. An Ahtna press release announcing the start of the drilling work said the well’s target depth was about 4,000 feet. The company statement also noted previous exploration wells in the region — Ahtna was a partner on one — hit high pressure water zones that hampered drilling. However, the Alaska Native regional corporation had taken steps to mitigate pressure risks, including drilling a smaller pilot bore to 1,100 feet before setting concrete castings, according to the company. Ahtna is the Alaska Native regional corporation for the upper Susitna and Copper River region. A commercial-quality natural gas discovery in the Glennallen area could provide a lower cost and cleaner energy supply to not only the Copper River region but also the Interior. It is seen as a potential long-term energy solution to the short-term Interior Energy Project, the state-owned Alaska Industrial Development and Export Authority’s effort to expand natural gas use around Fairbanks by trucking it north from the Matanuska-Susitna Borough. According to the AOGCC, the Tolsona-1 well reached its total depth on Nov. 22, after 54 days of drilling. Ahtna originally expected the drilling to take 26 days. A Jan. 6 Ahtna release stated the well was ultimately drilled to 5,500 feet on Dec. 5 to overcome challenges from unexpected complexities in the area’s geology. “We are proud that the Tolsona project delivered an outstanding safety record, provided employment and development opportunities for Ahtna shareholders and Alaskans, and that we were able to reach and evaluate the targeted zone,” Ahtna President Michelle Anderson said in the Jan. 6 release. At that time Ahtna was preparing for detailed analysis of the well data, the company said. According to the commission, the well was evaluated until Dec. 14, when the company applied to the commission to suspend the well. That application was approved the same day. A day later, the company reported that pressure was building in the well casing annulus — the area between the inner tubing and outer casing — to nearly 900 pounds per square inch. The pressure again built back to approximately 1,110 pounds per square inch after Tolsona bled it to zero, according to AOGCC documents. As a result, the commission approved continued suspension of well operations and the installment of a second mechanical tubing plug. The commission additionally wanted Tolsona to monitor the well pressure and provide weekly reports until Jan. 20. On Jan. 12, the commission approved Tolsona’s request to further install a back pressure valve in the well tubing at the end of the pressure reporting period. As a stipulation of installing the back pressure valve, Tolsona was required to provide monthly pressure reports to the AOGCC and give commission inspectors three days notice so they could witness the pressure readings. Shortly thereafter the alleged problems began. A March 6 AOGCC Notice of Violation issued to Tolsona Oil and Gas stated the company failed to report the well pressure on Jan. 20, but after a Jan. 23 follow-up by the commission, “Tolsona provided the data the same day with ‘apologies, we will not be late again.’” However, according to the March 6 notice, after not receiving the Feb. 20 pressure report, the commission did not hear back from Tolsona via email after Feb. 28 and March 2 phone calls were not returned. The commission subsequently sent an inspector to the drill pad March 3. The notice states that once on site, the inspector discovered that the well pressures had not been recorded over the past month; a Tolsona representative that met with the inspector did not know if the back pressure valve had been installed; and the Tolsona employee had not been trained to properly record the wellhead pressures. The April 11 AOGCC enforcement notice states that “Tolsona remains non-responsive and has failed to provide the required monthly well pressures for March 2017. Further, it alleges the company violated state regulations by not installing another pressure gauge on an outer well casing. In a May 30 statement, Ahtna said its subsidiary has taken immediate action to comply with the May 24 order, claiming Tolsona responded to the March 6 notice by informing the commission it was working to install the required equipment on the well, including the pressure gauge. Tolsona management did not receive the April 11 notice and “communication between Tolsona and AOGCC was unsuccessful until May 25,” according to Ahtna. “Action taken has included scheduled installation of required equipment this week and improvements in chain of command protocols,” according to the Ahtna statement. “The well has been monitored and monthly well pressure reading reports have been provided on time by Tolsona to AOGCC since December 2016, with the exception of February’s report, which was submitted late but confirmed received.” AOGCC commissioners said they could not comment on the matter to the Journal because it is still in adjudication. On June 1, Ahtna issued a follow-up statement, saying the wellhead work needed to comply with the commission's orders was completed a day prior. That included installing a back pressure valve and a pressure gauge to monitor potential pressure on the outer well casing, according to Ahtna. "The pressure reading on the (outer casing) after installation continues to be zero pounds per square inch. Tolsona appreciates and respects the mission of AOGCC to protect the public's interest in development of Alaska's resources," the June 1 statement reads. "Tolsona and AOGCC have worked cooperatively to address any issues." It also notes that the area surrounding the well is undeveloped and the driling pad is secured by a gate preventing public access, presumably in response to the commission's assertion that the company's actions potentially put the public at risk. The April 11 notice details the $380,000 proposed fine as $10,000 for failing to install the pressure gauge and another $10,000 for failing to submit the March 20 well pressure report. On top of that, the commission levied another $5,000 per day for each of the 50 days the gauge was not installed, from Feb. 20 to April 11, and $5,000 per day for each day the March 20 pressure report was past due. “Tolsona’s failure to provide the monthly well pressure readings on a timely basis for three consecutive months, along with its failure to monitor required well pressures, demonstrates Tolsona’s disregard for regulator compliance,” the April 11 AOGCC fine notice summarizes. That theme is continued in the most recent May 24 enforcement order, which contends Tolsona still had not responded to the commission’s March 6 notice. “There is no dispute that the violations occurred and, as of the time of this order, remain ongoing. Prior to sending this notice, AOGCC made numerous attempts to obtain Tolsona’s compliance. Tolsona has in large part stonewalled the AOGCC’s efforts to obtain compliance, including ignoring the Notice of Proposed Enforcement Action,” the May 24 order concludes. “Tolsona’s demonstrable disregard for regulatory compliance precludes any finding that it acted in good faith; any unmonitored over-pressured (wellbore) is deemed a serious violation which poses a serious and significant risk to public health and the environment. Although there was no injury to the public, the seriousness of the violation, in absence of any effort by Tolsona to correct the violation or prevent future violations and the need to deter such behavior weigh strongly in the penalty imposed.” Elwood Brehmer can be reached at [email protected]

Hilcorp looks ahead after Inlet incidents

Hilcorp Alaska leaders are ready to look ahead after a rocky start to 2017. The company currently has two drilling rigs working in Cook Inlet, on the Steelhead and King Salmon platforms, and recently announced a $75 million plan to ultimately reduce oil tanker traffic in the Inlet. Hilcorp found itself making unwanted headlines starting in early February when it reported a natural gas leak from one of its subsea pipelines in the central Inlet Middle Ground Shoal oil field offshore from Nikiski. The company took significant heat from environmental groups for not having a plan to immediately fix the gas leak, particularly because Cook Inlet is home to its own distinct population of endangered Beluga whales. Hilcorp representatives said at the time the damaged gas line — in about 80 feet of water — could not be repaired because the loose sheets of ice that drift through Inlet waters each winter put dive crews in unacceptable danger. Additionally, gas flows in the formerly oil-carrying eight-inch pipeline could be reduced but not completely cut off to keep the line from depressurizing and potentially allowing residual oil to escape and compound the problems. As a result, natural gas bubbled to the surface for more than two months, until divers installed a temporary repair clamp in the pipe April 13. Had it been an oil leak, the line could have and would have been shut in almost immediately, Hilcorp Alaska Senior Vice President Dave Wilkins emphasized in a May 17 interview. In the end, a sofa-sized rock rubbing on the pipeline was identified as the culprit of the leak; it wore a 3/16-inch by 3/8-inch hole in the line, according to the Alaska Department of Environmental Conservation, the state agency charged with addressing the matter. DEC issued its final situation report on the gas leak May 22. Divers finished permanent repairs to the pipeline May 19 and divers conducting an inspection of the repair the following day found no further bubbles or leaks, the report states. Less than two months after the gas leak was confirmed, on April 1 Hilcorp workers on the Anna oil platform sent word of what at the time was believed to be an oil spill after something struck the platform and a small slick was spotted on the water’s surface below. Originally believed to be a potential oil spill, the sheen dissipated quickly after it was first reported. The company concluded a large pan of river ice struck the northern Cook Inlet platform, causing about three gallons of natural gas condensates that had gathered in a gas flare fuel line to spill over into the water, Wilkins said. “When the jar happened — there’s an eight-gallon capacity in that flare gasline and there was five gallons that drained from the system,” Wilkins said. “My instructions were, ‘do a full investigation.’” The fact that the sheen disappeared — likely evaporated — lends credence to the conclusion it was gas condensate, not oil from an unknown source, according to Wilkins. He said the company has taken steps to assure condensates won’t collect in flare lines in the future. And despite the criticism and prolonged attention Hilcorp has received over the past few months, Wilkins said he would have his folks do it all the same again. “I’m very proud of the way Hilcorp responded. We did the right thing in both incidents,” he said. “Our indication was (the gas leak) was a low-risk, very minimal event. First and foremost, we’re not going to put people’s lives at risk, so we were making the right decision saying, ‘we can’t get in the water,’ so we acted appropriately in my opinion.” It’s believed the gasline could have started leaking as early as late December, but the exact date is still unclear. Hilcorp first identified a problem when employees noticed gas meter readings weren’t adding up. The line supplies fuel gas between the Middle Ground Shoal platforms, so it wasn’t the company’s utility gas customers missing product. At that point Hilcorp began doing flyovers of the area looking for the methane bubbles it finally found Feb. 7 to confirm the problem. “Keep in mind, this is a system; four platforms, multiple pipes. That’s what made it difficult,” Wilkins said. He added that the company is still gathering data and working to apply lessons learned to make sure there is not a repeat down the road. Hilcorp has an extensive diving season planned this summer to survey its subsea pipeline network. The Middle Ground Shoal leak and the fact that much of the Inlet’s oil and gas infrastructure — owned and operated mostly by Hilcorp these days — is upwards of 40 years old or older, has spurred efforts to evaluate the resiliency of the complex system. The Cook Inlet Regional Citizens’ Advisory Council, in concert with DEC, is prepping to conduct a comprehensive review of the Inlet’s offshore infrastructure. Congress established the Cook Inlet council and an identical body for Prince William Sound in 1990 in response to the 1989 Exxon Valdez grounding to act as an objective oversight group aimed at preventing future petroleum spills. CIRCAC Executive Director Mike Munger said in a previous interview with the Journal that Cook Inlet’s ever-changing weather, nearly unmatched tidal currents and fluctuations, and shifting winter ice can severely hamper spill response efforts, making prevention even more paramount. Hilcorp Alaska spokeswoman Lori Nelson said the company supports CIRCAC’s assessment. “(We) opened our doors to them,” Nelson said. “We’re going to be one of the primary information providers as far as what’s out there.” Wilkins said the company, which bought its way into Alaska through a series of purchases from Marathon and Chevron in 2012 and has spent more than $4.5 billion since, has a strong history of managing mature fields. The company’s spending has been $1.8 billion in acquisitions, $1.3 billion in investments and $1.4 billion in operating costs. Its infrastructure inspection program is robust and often goes beyond state and federal requirements, he said. “Pipes will last a long time if they’re cared for. Just because something is old doesn’t mean it’s useless,” Wilkins continued. “We’re a company that operates old assets and we understand how to do it and we train our people how to do it. “Am I guaranteeing nothing will happen? No, but we are well-trained to maintain and respond, as you’ve seen, if something does happen. We strive to get better every day.” A similar Inlet pipeline risk assessment commissioned by the council in 2005 concluded the infrastructure was, at least then, mostly in good shape due in large part to the fact that it was designed for capacity well beyond production levels at the time of the study. While Hilcorp’s business model in Alaska to-date has been to rejuvenate old fields cast aside by oil majors, the company is gearing up to spend approximately $75 million laying new pipelines on the Cook Inlet floor and converting some existing lines from gas to oil carriers to allow it to close the Drift River oil terminal. When the project is complete — which Hilcorp hopes will happen late next year — oil will flow from its west Inlet Granite Point facility under the Inlet directly to Tesoro’s Nikiski refinery via what is now the Cook Inlet Gas Gathering System. Repurposing the existing cross-Inlet gasline will mean installing a new gasline from the Tyonek platform to tie into the large Beluga gas transmission line on the west side of the Inlet. Also, oil flow that now goes from Granite Point south to the Trading Bay processing facility and on to the Drift River storage and tanker loading terminal will be reversed. The Drift River tank farm, with capacity in excess of 1 million barrels of oil, feeds the offshore Christy Lee tanker loading platform via pipeline. Its location in the shadows of Mount Redoubt, an active volcano, has long made it an environmental concern. The Drift River facility was partially flooded by a snowmelt-ash sludge in April 2009 after Redoubt erupted. Then operated by Chevron, the tank farm was shut down as a precautionary measure. Hilcorp restarted the then-40-year-old terminal in late 2012. Hilcorp has been investigating the prospect of a subsea oil transmission line — a lower spill risk option to tanker traffic — for some time, according to Wilkins. Its purchase of the Tyonek platform and associated pipelines last year from ConocoPhillips gave the company what it needed to make the project economic. “Now that there’s a pipeline system, we can utilize the existing infrastructure and do a project like this cross-Inlet pipeline project for far less than it would’ve cost another company, or to build new,” he said. The project should help Hilcorp produce from Alaska’s original oil and gas fields for another 20, 30 or 40 years, according to Wilkins. If his predictions prove true some of the fields could approach the century mark for production. “We feel this cross-Inlet pipeline will extend the life (of Inlet infrastructure), run it efficiently and be environmentally safe and responsible,” Wilkins said. Moving to the North Slope, Hilcorp is expecting to see the first draft of an environmental impact statement for its offshore Liberty oil prospect in the next month or so from the federal Bureau of Ocean Energy Management. About six miles offshore in the Beaufort Sea, the company plans to build a gravel island in the shallow water similar to how other nearshore North Slope oil discoveries have been developed. Hilcorp, which bought into Liberty in 2014 as part of a $1.25 billion deal with BP, estimates the long-awaited project could produce up to 70,000 barrels of oil per day at its peak. Elwood Brehmer can be reached at [email protected]

Delays continue to beset Interior gas project

Long challenged by unavoidably thin economics, the Interior Energy Project is now facing other pressures that are starting to force the hands of its developers. The Environmental Protection Agency recently changed its classification of winter air quality problems in the Fairbanks North Star Borough from “moderate” to “serious.” Additionally, the waning availability of a state tax credit for construction of a liquefied natural gas storage facility will require construction of the 5.25 million-gallon LNG storage tank to start this fall for it to be eligible for the tax credit at all, according to project leaders. Finally, there is the ongoing need for a natural gas contract not only to supply future customers that will hopefully be attracted to the project, but also for Fairbanks Natural Gas’ existing customer base. On top of all that, the Alaska Industrial Development and Export Authority and the Interior Gas Utility are still working to finalize the sale of Pentex Alaska Natural Gas Co., FNG’s parent company, from the state investment authority to the borough-owned utility. That deal, which would ostensibly transfer the IEP management from AIDEA to IGU, was announced in January and was initially supposed to be done by March 31. IGU General Manager Jomo Stewart said in an interview that AIDEA and the utility are still moving towards integrating Pentex-FNG and IGU as quickly as possible. “You’ve got complex scheduling to work on a complex suite of documents to work on a highly complex project with lots of moving parts and frankly a number of mission critical elements that are complex in amongst themselves,” Stewart said. Combining the startup and existing Fairbanks-area gas utilities has largely been viewed as the natural course of action since AIDEA purchased Pentex for about $52 million in 2015. It would provide numerous operational efficiencies and allow the utilities to source gas from a single contract. Expanding Pentex’s small Southcentral LNG plant — from which it trucks LNG to its Fairbanks customers now — and getting the associated LNG storage underway in Fairbanks are a couple of those mission critical elements. FNG first proposed building the LNG tank, estimated to cost about $42 million, several years ago before being purchased by AIDEA. But actually building the additional LNG storage has been unnecessary to this point as the project lacks a gas contract to fill it. However, the project should be eligible for a state tax credit of up to $15 million if it’s up and running by the end of 2019 to beat the sunset date of the credit; and it’s expected to take about two years to complete. “We’re not going to miss another build season,” Stewart said. “There is a full, solid commitment that that storage is going to get started this fall.” Whether or not IGU is ever reimbursed for the tax credit is another matter — it’s part of the state’s larger oil and gas tax credit program to which Gov. Bill Walker has vetoed funding the last two years as the state grapples with massive budget deficits. But Stewart said the utility does not want to lose “the very opportunity to be in line” for the credit payment. Adding 3 billion cubic feet, or bcf, of liquefaction capacity to the LNG plant that currently processes about 1 bcf of gas into LNG per year should take about 18 months. AIDEA’s Interior Energy Project team has also been trying to get a natural gas supply from Cook Inlet producers on terms favorable enough to keep the project viable for more than a year. The desire to secure a long-term gas contract is still there, but Stewart said the reality of the situation could amend what is accepted. “The mindset is evolving that we’ll be doing it in increments — that it’s ok to do things on an incremental basis,” he said. The challenges with the gas contract have always been that it is for a relatively small amount of gas, which makes it harder to secure a favorable price, and will require the producer to rely on the expectation that gas demand will grow over time. Challenging the gas contract even further is the fact that low oil prices have lessened the price of fuel oil to the point where it is price-comparable with what AIDEA and the utilities hope to deliver natural gas to customers for, thus eliminating the major impetus for residents to invest in converting their homes from fuel oil heat to natural gas. However, FNG’s gas supply contract for its existing customers expires next April, exacerbating the urgency of the situation. FNG reached a $15-million deal in late 2014 for a 10-year gas supply from Hilcorp Energy, the major Cook Inlet producer, that included selling the LNG plant to the producer. But it was rejected by then-Attorney General Craig Richards over concerns Hilcorp would control the entire gas supply chain to Fairbanks and could manipulate pricing to its benefit. The economic hurdles the IEP faces have morphed the project from one primarily aimed at lowering energy costs in the Interior to one focused on improving the region’s winter air quality, which can be the worst in the country when ultra-cold and dense air traps emissions from vehicles, home furnaces and woodstoves — all running full bore to keep their owners warm. The EPA, to that end, has long been watching the IEP and efforts by the Fairbanks North Star Borough to improve winter air quality in the region. AIDEA’s IEP manager Gene Therriault said during a May 18 AIDEA board meeting that the EPA’s Region 10 officials ask for a project update each time they visit Fairbanks. Therriault noted that the latest omnibus spending bill passed by Congress includes $30 million in competitive EPA grants for communities not in compliance with federal air quality standards, up from $20 million in the last budget cycle. The Fairbanks Borough won $2.5 million last year to fund residential woodstove change-outs to cleaner burning heating options. Fairbanks-area AIDEA board member Gary Wilken questioned whether the borough could use any future grant funds for residential natural gas conversions, which will underpin the entirety of the project. Therriault said the EPA wants the funds to go towards immediate steps to improve winter air quality, but that the relationship the borough is building with the EPA could lead to conversion assistance or incentive funding when the time comes. Wilken, worried the project could still be stuck in the same chicken-and-egg scenario, said the help is needed now. “$5 million or $10 million goes a huge way in our project when we finally turn the valve on gas, so that’s not the time to start getting money out of the federal government; now’s the time to do it,” he said. Elwood Brehmer can be reached at [email protected]

$37 million claim against Legislature gets day in court

The owners of the former Downtown Anchorage Legislative Information Office building contended in a May 19 state Superior Court hearing that legislators did not afford them appropriate recourse on a $37-million contract claim after the Legislature decided to leave the six-story building last year. Jeffrey Feldman, attorney for 716 West Fourth Avenue LLC, argued to Superior Court Judge Mark Rindner during the nearly two-hour hearing that because then-Legislative Council Chair Sen. Gary Stevens of Kodiak did not hold his own hearing on the matter in which 716 was allowed to present its case, Stevens’ decision to deny 716’s contract claim was based on incomplete evidence and therefore faulty. Stevens and the full Legislative Council followed “nothing that would seem to reflect our common notion of due process,” Feldman told Rindner, adding that Alaskans denied a Permanent Fund Dividend are entitled to a hearing and thus have more recourse in disputes over much less money. Legislative Council attorney Kevin Cuddy responded that 716 — the LIO building owner group led by longtime Anchorage developer Mark Pfeffer — provided 50 pages of single-spaced briefings and another 70 exhibits to Legislative Council as evidence and could have provided anything else it wanted for Stevens to base his decision. “I understand that every plaintiff is going to want another bite at the apple,” Cuddy said. He argued further that any new facts that could be brought to light in a trial de novo, or evidentiary hearing, would be immaterial because at its core the case is about the contract between 716 and Legislative Council and that contract was followed, just to the detriment of 716. “716 has received exactly what it could’ve expected based on the terms of the contract,” Cuddy said. Last October, Stevens denied 716’s claim for $37 million on the basis that it was not in the public’s interest for the Legislature to pay out the purported damages. When 716 appealed Stevens’ decision to the full Legislative Council, the 14-member committee deferred to Stevens’ ruling and denied the appeal without hearing from 716. Legislators moved out of the Downtown Anchorage building late last September and into Midtown office space purchased for $11.8 million from Wells Fargo via the state capital budget. In late 2015, public pressure over the unpopular 10-year $33 million lease pushed the council to start looking for a way out of the building, which was custom-built for the Legislature in 2014. Before voting to leave the LIO, however, the Legislative Council agreed in principle with 716 to buy the building for $32.5 million. At the time, legislators said it was a way to get out of the lease that would in the long-term save the state money and give it a marketable asset as well, while avoiding the potentially costly legal battle that has since ensued. That deal evaporated quickly when Gov. Bill Walker said he would veto the capital appropriation to buy the building, saying it would be inappropriate for the state to spend that much on office space when government services — and eventually PFDs — were being significantly to solve a nearly $3 billion budget deficit. Lacking the Legislature’s monthly lease payments of about $280,000, 716 has since defaulted on its $28.6 million loan on the building with Florida-based EverBank, according to the court appeal document. The lease, as is common in government contracts, contained a “subject to appropriation” clause, meaning it is only valid if the full Legislature funds it. When the Legislature, at the recommendation of the council, decided not to pay the lease, a termination letter was sent to 716 by Legislative Affairs Agency officials citing the appropriation clause as the reason why. That should pretty much end the case, according to Cuddy. However, 716 appealed the administrative rulings to the Superior Court on an estoppel claim — that the developers invested large sums of money and made good on their end of the deal based on assurances that the Legislature would reciprocate. To that end, Feldman highlighted a May 2016 letter from Cuddy to EverBank, in which Cuddy wrote that a separate Superior Court ruling invalidating the lease would force the Legislature to vacate the offices and find alternative space. The dueling reasons for leaving indicate legislators could have been disingenuous in why they moved and necessitates discovery of more evidence so Rindner can rule with a complete set of facts, according to Feldman. During what was a fairly informal oral argument proceeding that could be likened to a discussion between the attorneys and the judge, Feldman told Rindner: “You’re trying to tease out answers from a record that simply doesn’t exist.” Rindner responded that administrative appeals lacking facts are usually remanded to the administrative officer for further discovery, to which Cuddy agreed. “I don’t recognize this process,” Feldman said simply. Rindner also pondered whether potentially subpoenaing legislators’ emails and other documents to allow the court to get to the bottom of why they ultimately walked away from the offices could violate the fundamental separation of powers between branches of government. Rindner said he would take the arguments under advisement, but did not give a timeline for a ruling. If the case is remanded to the Legislative Council, Juneau Rep. Sam Kito, who also served on the committee last year, now chairs the council. Kito was often the lone “no” vote against taking steps to leave the Downtown Anchorage LIO, citing legal concerns and a worry that invoking the “subject to appropriation” clause would damage the state’s credibility in future deals. The Alaska Bankers Association, Alaska Housing Finance Corp. officials and other state finance leaders have said leaving the LIO in the manner the Legislature did could lead to higher interest rates on state debt, fewer contractors and landlords willing to work with state agencies and other financial consequences as well; Feldman repeated those points in his argument. Elwood Brehmer can be reached at [email protected]

Senate passes its version of oil tax credit reform

Now the oil tax debate in the Legislature can really start. The Republican-led Senate passed House Bill 111, this year’s oil tax credit legislation, on May 15 by a 14-5 vote along caucus lines. On May 16, a concurrance vote in the House failed 17-22, setting up a conference committee process for the bill. The Senate version of the bill ends the cashable tax credit “experiment,” Anchorage Republican Sen. Cathy Giessel said in the floor debate, along with preventing companies producing oil in the state’s largest fields from using deductible credits to take their tax obligation below the 4 percent gross minimum tax. Amendments by Anchorage Democrat Sen. Bill Wielechowski to increase the minimum tax, decrease deductible tax credits and require producers to disclose additional financial information to the state were shot down. “By hardening the (tax) floor, by moving what was a cash credit to an obligation, it is an increase on companies,” Giessel said. It is less of a tax increase than the version of HB 111 the Democrat-led House Majority sent to the Senate. That House legislation also increased the production tax at oil prices less than $100 per barrel largely by eliminating the per-barrel credit on the large legacy oil fields, which is currently employed to significantly lower the effective tax rate, while lowering the base tax rate from 35 percent to 25 percent. Senate Republicans have said all session that they were open to cutting the state’s remaining refundable tax credits for explorers and small producers, mostly on the North Slope, but that rewriting the underlying production tax was off the table. Gov. Bill Walker and the House Majority share the Senate Republicans’ sentiment about ending the refundable tax credit program while the state still struggles with budget deficits exceeding $2.5 billion per year. But House Democrats also contend that the current oil tax code supported by Republicans was written when oil prices were greater than $100 per barrel and doesn’t provide the state adequate revenue at $50 to $70 per barrel, which most industry experts expect will continue into the foreseeable future. The House’s version of HB 111 would raise between $80 million and $100 million per year in new North Slope production taxes in the near term, according to Department of Revenue projections. House Resources Co-chairs and primary authors of the original HB 111, Anchorage Democrat Reps. Geran Tarr and Andy Josephson, commended the Senate for culling out the state’s remaining cashable tax credits, which Tarr said was “long overdue” in a caucus release, but said the Senate’s bill was rejected because it largely ignores the state’s current fiscal situation. “The Senate Majority took our good bill that was developed in the open, with advice from the experts and the input of Alaskans, and replaced it with a bad bill that continues many of the flaws that have placed Alaska in our current precarious financial position,” Josephson added. “The best course of action is to take this bill to a conference committee where an acceptable compromise can be reached that protects the state during these low oil prices, while still keeping Alaska competitive as a place for future oil industry investments.” The Senate version saves the state from paying out future refundable tax credits, expected to accrue at about $150 million per year, which the House bill does, too, but doesn’t change the base production tax. Still, the industry isn’t thrilled about it. “Today, the Alaska Senate passed the seventh change to Alaska’s oil tax structure in 12 years. It eliminates cash payments to companies and adds $1.2 billion to the State of Alaska’s treasury over the next 10 years,” Alaska Oil and Gas Association CEO Kara Moriarty said in a formal statement. “Alaska’s oil and gas industry has played a large part in contributing to the state’s fiscal solution for more than 40 years. With this bill, the industry will contribute even more to the state’s fiscal solution.” While the state will keep the projected $1.2 billion it would have spent on some tax credits in its coffers as Moriarty noted, the formerly refundable credit certificates will be converted to deductions companies can apply against future production taxes in the bills passed by both bodies. Allowing a company to deduct expenses and losses against a tax liability is common for profits-based taxes such as Alaska’s oil production tax, but it does mean there will be foregone future production tax revenue. The Department of Revenue estimates turning the credits into deductions, along with some existing carry-forward lease expenditures, could allow Slope operators to generate up to $1.4 billion in production tax deductions over the next 10 years based on the Senate’s legislation. How much revenue the state is willing to forego and whether or not there will be an increase to the base production tax paid by producers will be the basis for the HB 111 House-Senate conference committee debate, presuming the House Majority holds together and rejects the Senate’s version of its bill. Other outstanding bills With the exception of the capital budget, which passed the Senate May 12 and is now in House Finance, the House and Senate each passed versions of this year’s major pieces of legislation by May 17. Conference committees have been appointed and met on the operating budget and on Senate Bill 26, Gov. Walker’s Permanent Fund bill; however, significant action to resolve the bodies’ differences in the pieces of legislation has not taken place, at least publicly. The Senate folded legislation to allow the state to comply with the controversial federal Real ID Act into a bill establishing training for police officers to better manage situations involving individuals with non-apparent disabilities. The bill, House Bill 16, passed the Senate May 15 despite concerns from some that adding the Real ID provisions could violate a clause in the Alaska Constitution requiring legislation be limited to a single subject. The move was made to fold the two together in order to allow the House to bypass the committee process for a standalone Real ID bill — a process that could have caused the state to miss a May 17 federal deadline to try to comply with Real ID — and instead simply concur via floor vote with the Senate’s version of HB 16, which the House passed previously. ^

House Finance co-chair: Committee will restore AK LNG funds

A last-minute move by the state Senate to pull $50 million dedicated to the Alaska LNG Project and spend it on other state services will be reversed in the House Finance Committee, according to committee co-chair Rep. Paul Seaton. The Homer Republican, who is a member of the Democrat-led House Majority, said in an interview Friday that he and fellow Finance leader Rep. Neal Foster, D-Nome, have no interest in de-funding the Alaska Gasline Development Corp., which is leading the project, at this point. An amendment by Sen. Mike Dunleavy, R-Wasilla, to the capital budget bill that passed the Senate Thursday reappropriated half of the $50 million from the Alaska LNG Project Fund to the departments of Law, Public Safety and Transportation to hire district attorneys, state troopers and support road maintenance. The other $25 million was redirected to the state Public School Trust Fund. AGDC President Keith Meyer has said the state-owned corporation plans to operate on its previously appropriated funds — about $102 million at the beginning of the year — through the end of fiscal year 2018, which is June 30, 2018, in recognition of the state’s major budget problems. When the AGDC board of directors approved the spending plan in early February the corporation had about $76 million in the Alaska LNG Project Fund and another $26 million in the In-State Natural Gas Pipeline Fund. Meyer and Gov. Bill Walker have repeatedly said AGDC will spend 2017 initiating the project’s voluminous environmental impact statement, or EIS, with the Federal Energy Regulatory Commission; determining if there is a global appetite for Alaska’s North Slope natural gas; and securing gas customers and construction financing to pay for the estimated $40 billion gas pipeline and LNG export project. “We are committed not to interrupt the FERC process and the solicitation of investors” in Alaska LNG, Seaton said. AGDC submitted its EIS application to FERC last month and Meyer is currently on a marketing trip to China, according to an AGDC spokeswoman. Finishing the approximately two-year FERC EIS will likely cost the state upwards of $100 million, meaning AGDC could need a cash infusion from the Legislature during next year’s session, but by that point the corporation hopes to have deals in place that it can prove to legislators it is worth funding. Pulling the funding would undoubtedly challenge AGDC’s efforts and there has been ample bipartisan skepticism in the Legislature towards the project over the past year since the state’s former partners in the project, BP, ConocoPhillips and ExxonMobil early in 2017 indicated a desire to slow the project and hope global LNG prices improve. BP signed a one-year memorandum of understanding through the end of 2017 to assist AGDC with marketing and other aspects of the project. Global LNG prices, historically linked to oil markets, have fallen dramatically over the past two years and hampered the economics of Alaska’s and other LNG projects worldwide. Seaton was critical of the lack of public vetting of the amendment to strip the AK LNG funding, as the details of the amendment were not read on the Senate floor. Dunleavy simply proposed what was the fourth amendment to the budget and it was adopted without objection, discussion or a vote. Seaton also said reversing the funding transfer will not impact the departments in line for the cash because the prosecutor and trooper positions were already separately funded in the House and Senate versions of the operating budget, where those types of expenses are usually addressed. Additionally, he noted the trooper and district attorney funding in the capital budget is a one-time spend, meaning those positions would be eliminated next year unless more money was added either to the base operating budget or again to the capital budget as one-off appropriations. The House and Senate also approved a nearly $10.4 million allocation to pay for AGDC’s fiscal 2018 operations and personnel expenses in its operating budget. That money would come out of the $102 million in gasline funds as it has for several years. However, the Senate’s capital budget did not include a request by AGDC to transfer $14 million from the In-State gasline fund to the Alaska LNG Project Fund so the corporation can legally spend the cash on the large project. Seaton said he couldn’t comment on the House Majority’s plans for the $14 million request because he hadn’t yet discussed it with Foster, who chairs the capital budget in the House. Elwood Brehmer can be reached at [email protected]

New life for North Slope 100 million years in the making

All of a sudden, Alaska has more than 400,000 barrels per day of new oil potential. The North Slope, dismissed by many in recent years as a has-been conventional oil basin unable to keep up with the hip-now-with-it-and-wow shale mania of the Lower 48, is on the verge of reinvention. In just the past year, Caelus Energy, ConocoPhillips and the Armstrong Energy-Repsol partnership have all announced oil discoveries capable of producing up to, or well in excess of, 100,000 barrels per day. And they’re all related. To find the link, one only needs to look back about 150 million years or so when the nearby Brooks Range began to grow, according to state petroleum geologist Paul Decker. The billions of barrels of oil the companies believe they have found are all located in the Brookian geologic sequence: layers of sandstone carried off the then “new” mountain range by wind and water between 90 million and 105 million years ago. “The Brookian sequence is all that matter that was shed by erosion from the Brooks Range,” Decker explained in an interview. It’s very similar to what the Colville and Sagavanirktok and Canning rivers are doing farther to the north today. The weight of the rising mountains — oldest to the west — pressed a trough in the Earth’s crust at their base, providing a place for the first Brookian sediments to settle, explained Mark Myers, a renowned Slope geologist, former Alaska Department of Natural Resources Commissioner and U.S. Geological Survey Director further. That trough, or geologic foreland basin, was also filled with ocean water and river deltas when the Arctic coast was farther south than it is today, Myers added. During those prehistoric times of higher sea levels, the Brooks Range sediments were settling to the ocean floor that is now the plain of the North Slope. The smallest sediment particles were naturally carried the farthest, to the then base of the continental shelf, before stopping. The larger sands fell out upstream and on top of the deltas, above the shelf edge, or fore set, according to Decker. Those first sediment layers make up the base of the Brookian sequence and the two zones targeted in the latest North Slope oil prospects: the Nanushuk and Torok formations. “The sands in the Torok tend to accumulate at the basin of the floor, right where the fore sets kind of run out of slope angle and there’s nothing to keep propelling those sediments, so they drop out there at the basin floor,” Decker said. The larger, Nanushuk sands came to rest above the Torok and as sea level retreated rivers carried the sediments farther and farther out to meet the ocean, eventually forming the sandstone layers found today, Decker and Myers said. This is where the oil companies come in. Dallas-based independent Caelus Energy came to Alaska in early 2014 with its sights set on the Torok sands. The finer Torok sandstone has smaller gaps between its grains making it less permeable than the Nanushuk. For that reason, Caelus hydraulic fractures its North Slope wells to create pathways for the oil to travel. Myers said the Torok at Caelus’ Smith Bay discovery is part of a large “submarine fan play,” or the edge remnants of a former river delta. Last October, Caelus Energy CEO Jim Musselman announced his company had discovered upwards of 6 billion barrels of oil at Smith Bay, a near shore prospect in state waters on the edge of the National Petroleum Reserve-Alaska and more than 100 miles from existing North Slope oil infrastructure. Caelus estimates full development of Smith Bay could produce up to 200,000 barrels of oil per day at its current projected size, but Musselman said he could foresee Smith Bay growing to 10 billion barrels once all of his company’s leases in the area are better examined. “Giant fields get bigger with time,” Musselman said when the Smith Bay find was made public. Caelus plans to drill an appraisal well next winter to get a better idea of what exactly it has. The Nanushuk Project, now operated by Armstrong Energy, is not named that by coincidence. It is targeting the Nanushuk formation, which generally sits above the Torok. With 16 wells drilled in the formation since 2011, the Nanushuk Project is better delineated within the Pikka Unit than Smith Bay at this point; and Armstrong CEO Bill Armstrong has told the Journal he believes it could produce up to 1.5 billion barrels of light crude at a peak rate of 120,000 barrels per day. “The (prospect) that we just found is the first of its kind on the Slope, but mark my words, it’s going to be the new hot play,” Armstrong said in a September interview. By January it was repeated for the first time, when ConocoPhillips made news with its Willow discovery, another Nanushuk play in the National Petroleum Reserve-Alaska to the southwest of Armstrong’s and Repsol’s work. ConocoPhillips declined to comment further on the Willow prospect for this story, but the company’s Alaska leaders said when the discovery was announced that it contains about 300 million barrels of recoverable oil that could be pulled at a rate of up to 100,000 barrels per day. The fact that ConocoPhillips, a typically conservative oil major, is willing to go public with a 300 million-barrel projection for Willow off of the results from just two exploration wells drilled in early 2016 could indicate the reservoir is on the scale of that found by Armstrong and Repsol, Myers surmised. “We’re not looking at little small plays; we’re looking at very large plays,” he said. “You’ve got two of these now and there’s more running room for that (Nanushuk) play.” Not long after, in mid-March, Repsol and Armstrong revealed very promising results from the Horseshoe well, an exploration well drilled last winter about 20 miles south of their Nanushuk Project. Armstrong said then that the Horseshoe well confirmed the oil-bearing Nanushuk reservoir they tapped into was much larger than first thought and could double the confirmed size of the original prospect. Repeatable discoveries Decker said the Brookian plays are likely repeatable beyond those already found because the Nanushuk and Torok formations extend west to east across most of the North Slope. The state Division of Oil and Gas has a long seismic cross-section chart of the Slope that shows numerous buried fore set breaks that formed as the ocean retreated over millions of years. The seismic fore set marks — called “shazams” by geologists, at least according to Decker — can be a starting point for oil hunters in search of the subtle stratigraphic traps that hold oil in the Nanushuk and Torok sands. That’s because those fore sets are a better than average place for the sandstone to peter out; and if there are shale or other impermeable rock layers above and below the sandstone formation, the oil can become trapped in the long, fading sliver of reservoir-quality rock. “It’s the stratigraphic subtleties of how are the sands and the intervening shales distributed and do they actually completely seal at the top,” Decker said. The fact that the North Slope coastal plain — and the edge of the continental shelf — developed in steps mostly from west to east with a slight northerly component could mean the Nanushuk oil fields will generally be long north to south and narrow east to west, he added. That feature can be seen in the Nanushuk Project. Armstrong said the Horseshoe well delineated an oil field more than 20 miles long north to south and about 3 miles across. Caelus also holds large tracts of mostly uninspected state leases to the east of Prudhoe Bay that company officials are excited about and also has the smaller Oooguruk and Nuna developments near Armstrong’s Pikka Unit, which holds the large Nanushuk Project. Another positive of the Brookian formations is that they are younger and shallower than the more commonly exploited Beaufortian formations on the Slope, making them somewhat easier, and cheaper, to drill. The Beaufortian sands that generated the giant Kuparuk field are up to about 135 million years old and can be found at depths between 6,000 and 7,000 feet, according to Decker. And Prudhoe Bay wells often have to go to 9,000 feet before finding oil, while Nanushuk sands usually start appearing at about 4,000 feet. Hidden in plain sight Averse to and lighter than water, oil and natural gas always run up from their source rock, and thus require a tight seal rock layer to collect the hydrocarbons and prevent them from continuing upward. “Where it’s not saturated with hydrocarbon, any pore space in the subsurface is saturated with water,” Decker said. Historically, North Slope explorers — and oil drillers worldwide, for that matter — have looked for large, structural oil traps, or “bumps” in seismic data as the best places to start drilling. These bumps in a layer of seal rock usually appear as an upside down bowl on a seismic printout and are a prime place for oil or gas to accumulate on its voyage upward. However, the North Slope is almost as flat underground as it is above, which means the large, obvious irregularities in the rock formations that stored oil for the big fields of Prudhoe Bay and Kuparuk have mostly been exploited, Armstrong said in a previous interview. Enter the stratigraphic trap. “It’s traps that form because of changes in the layers horizontally. You have a sand; that sand thins out and goes away and meanwhile the shale below it and above it are still there,” Decker said. “With a wedge of shale below and shale above that’s going to make a nice permeable sort of wedge for (oil) to build up and that’s the nature of these stratigraphic traps.” Targeting subtle linear stratigraphic traps is not new, Decker said. It’s been done in other basins with other formations, but those holding the cash have long been scared of testing the unproven play in Alaska by employing an expensive North Slope drilling rig. “The concept of stratigraphic traps has really been known to be a viable concept in a very general sense for 60-plus years. I had a college professor who tried to get Shell to drill one in Wyoming back in the 1950s and they’re like, ‘Nah, we’ll stick to our domes,’ and the concept was proven up by another company a few years later,” Decker recalled. He noted several of the wells the Navy drilled in the NPR-A in the late 1940s hit Nanushuk oil and gas, but in quantities too small and in places far too remote to make development worthwhile. Other oil basins are simply at a more mature stage of exploration, Myers and Decker concurred. Armstrong acknowledged the Nanushuk formation he and Repsol struck was not their primary objective when they first began exploring, too. “It was a secondary objective and it was almost invisible on the seismic, so you can see why everybody missed it,” Armstrong said. The Nanushuk Project is tucked between the large Alpine and Kuparuk fields operated by ConocoPhillips. To that point, a top ConocoPhillips Alaska official told the Journal that “we ask our geologists every day” how they did not see what Armstrong found. The big change really came in the form of 3D seismic mapping. Myers and Decker almost identically likened the 3D images to “an MRI of the Earth” juxtaposed against the X-ray-like 2D seismic oil and gas explorers relied upon for decades. “Good seismic made all the difference in being able to prospect at a lower risk for stratigraphic traps. It’s the subtlety of the traps” that necessitates the detailed data, Decker said. Extending the play Finally, with Caelus expanding Slope exploration to the north and west with its Torok find at Smith Bay, a couple other small companies are working to complete the Brookian chain far to the south. Australian-based 88 Energy Ltd. and Houston independent Burgundy Xploration Inc. are currently drilling an appraisal well into the HRZ shale zone on acreage about 60 miles south of Prudhoe adjacent to the Dalton Highway. The Icewine-2 well was spudded April 24 and hit 10,715 feet the morning of May 8, according to an 88 Energy release. The partners plan to flow test the well in late June. If the Icewine Project is developed, it could be Alaska’s first foray into the shale fracking that has turned the petroleum industry on its head. “We think that for a lot of the Brookian system, until we have better information, the assumption is that the HRZ shale is the most likely, most readily explainable source rock.” Decker said. “At the same time the Brooks Range was going up, this Colville basin was going down and the first deposits out there were pretty well starved. You didn’t have sands coming in; all you had was organisms dying in the water column and raining down and clay particles raining down so that makes really good source rocks.” Eventually, those source rocks were covered with millions of years of sediments to form what is the Slope today. While the economics of North Slope shale production seem sketchy to many, particularly at today’s oil prices, estimates from the first Icewine well indicate nearly 1 billion barrels of oil and natural gas condensates could be there for the taking, and a resource of that size would do nothing but help the project’s economics. If the second Icewine well is successful, the 400,000 barrels per day-plus of prospects figure will have to be revised upward soon. Elwood Brehmer can be reached at [email protected]com.

Senate Finance OK’s capital budget including tax credit funds

With the oil tax credit bill on the backburner, the Senate Finance Committee approved a capital budget bill May 9 that includes $288 million to pay down the state’s growing tax credit obligation. Finance Co-chair Sen. Anna MacKinnon, R-Eagle River, said the appropriation, if agreed to by the House and Gov. Bill Walker, would cover roughly one-third of the about $900 million in refundable tax credits the Department of Revenue is projecting the state will owe by June 30 at the end of fiscal year 2017. The $288 million appropriated to the Oil and Gas Tax Credit Fund is the last cash left in the Statutory Budget Reserve Fund, or SBR, savings account. Last spring, state budget managers discovered the SBR still had $288 million in it because the 2015 fiscal year deficit was slightly smaller than expected — but still more than $3 billion. The Democrat-led House Majority has sharply criticized the state’s refundable oil and gas tax credit program. However, House Democrats have agreed to appropriate hundreds of millions of dollars to the Tax Credit Fund in the past two budget cycles, acknowledging that, like it or not, the credits are a debt the state must pay at some point. Walker has ultimately vetoed portions of those credit appropriations — $200 million out of $700 million in 2015 and all but $30 million out of $460 million in 2016 — before signing the budget bills. Walker contended the state cannot afford the payments without separate substantial deficit reduction measures and new revenue. The current version of House Bill 111, the legislation to repeal the refundable tax credit program that is currently sitting in Senate Finance, would eliminate the Tax Credit Fund come Jan. 1, 2018. But because the capital budget takes effect July 1, the first day of the 2018 fiscal year, the Department of Revenue would have six months to pay out the $288 million if the bills pass the Legislature looking like they do now. The credits are paid on a first-in, first-out basis, meaning companies holding the oldest credit certificates would be paid first. According to Revenue officials, there were $477 million in certificates awaiting repurchase on Jan. 1 and the state has issued $600 million in refundable certificates this fiscal year. About $132 million of those issued certificates have been paid, sold to another company to be used against tax liability or repurchase had not been requested as of Dec. 31, 2016. The big provision in the Senate’s version of HB 111 would switch current, cashable 35 percent net operating loss, or NOL, credits, to a more traditional carry forward tax deduction for small producers and explorers when they have production tax liability. It would also allow small producers — those with less than 50,000 barrels per day of production — to use the $5 per barrel tax credit on oil from new fields to take their production tax obligation below the 4 percent gross minimum tax. The Revenue Department projects that provision would cost the state between about $20 million and $40 million per year in forgone revenue at forecasted oil prices. Overall, the bill is expected to save the state about $115 to $150 million per year by eliminating the directly refundable tax credits, according to Revenue projections. An inverse provision to prohibit loss deductions from taking a producer’s tax liability below the minimum tax on oil from the large legacy fields would increase tax revenue at market prices of about $40 per barrel or less, prices at which the major producers would be expected to start incurring losses. The “hardening” of the tax floor is not expected to have a revenue impact at current and forecasted oil prices, however.

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